Method of fracturing formations

ABSTRACT

Granules containing a gel breaker are used in a well treatment involving the use of a gelled fluid. The granules exhibit delayed release of the breaker to permit placement of the gelled fluid into the subterranean formation.

FIELD OF THE INVENTION

The present invention relates generally to the treatment of subterraneanformations using gelled liquids. In one aspect, it relates to gelledfracturing fluids. In another aspect, the invention relates to the useof granules containing breaker chemicals in the fracturing and gravelpacking operation. In still another aspect, the invention relates to thegranules per se containing breaker chemicals.

DESCRIPTION OF THE PRIOR ART

Hydraulic fracturing has been widely used as a means for improving therates at which fluids can be injected into or withdrawn fromsubterranean formations surrounding oil wells and similar boreholes. Themethods employed normally involve the injection of a viscous fracturingfluid having a low fluid loss value into the well at a rate sufficientto generate a fracture in the exposed formation, the introduction offluid containing suspended propping agent particles into the resultantfracture, and the subsequent shutting in of the well until the formationis closed on the injected particles. This results in the formation of avertical, high-conductivity channels through which fluids can thereafterbe injected or produced. The conductivity in the propped fracture is afunction of the fracture dimensions and the permeability of the bed ofpropping agent particles within the fracture.

In order to generate the fracture of sufficient length, height, andwidth and to carry the propping agent particles into the fracture, it isnecessary for the fluid to have relatively high viscosity. Thisviscosity in aqueous liquids is provided by the addition of polymers,frequently referred to as gelling agents. Following the treatment of thewell, it is desirable to return the aqueous liquid to its low viscositystate, thereby permitting the fracturing fluid and polymer to be removedfrom the formation and the propped fracture. The highly viscous liquid,if left in the fracture, would impede the production of formation fluidsthrough the propped fracture. Moreover, the residue of the polymer onthe fracture face and in the pores of the propped fracture wouldsignificantly reduce fluid permeability therethrough.

To avoid these undesirable after effects of the polymer and polymerresidue, it is now common practice to employ in the fracturing fluidchemicals ("breakers") which degrade the polymers. U.S. Pat. No.4,741,401 discloses a number of oxidizing agents contained in capsulesfor breaking the fracture fluid. U.S. Pat. No. 3,938,594 discloses theuse of sodium hypochlorite solution, acid, micellar solutions, andsurfactants for degrading the fracturing fluid polymers. Otherreferences describing breakers include U.S. Pat. Nos. 3,167,510;3,816,151; 3,960,736; 4,250,044; 4,506,734; and 4,964,466.

As described in detail in SPE Paper 18862, published Mar. 13-14, 1989,some breakers in fracturing fluids for shallow low temperature (100degree Fahrenheit) treatments are satisfactory for certain polymer gels.This paper further confirms that certain conventional breakers are noteffective in fluids gelled with polymers crosslinked with organometalliccompounds. For deep, high temperature (160 degrees Fahrenheit and above)wells, polymers crosslinked with organometallic compounds are generallyemployed as aqueous viscosifiers. The organometallic crosslinkers weredeveloped for high temperature service exhibiting excellent stability upto about 350 degrees Fahrenheit. Other crosslinkers, such as boratecompounds, have an upper temperature limit of about 250 degreesFahrenheit. Moreover, in deep high temperature wells, particularly wellsat temperatures in excess of 160 degrees Fahrenheit, breakers that arenot "delayed breakers" cannot generally be used because they tend todegrade the polymer prior to completion of fracture generation phase ofthe operation and/or placement of the proppant. Many of these breakersare pumped into the formation after placement of the fracturing becausethese breakers immediately start to degrade the viscosity enhancer inthe fracturing fluid upon contact. In such cases, additional time andlabor are needed to effect the reduction of the viscosity of fracturingfluids introduced into the subterranean formation. The use of organicbreaker such as alkyl formate may alleviate this problem, since they canbe applied along with the fracturing fluid. But these types of breakersrely on certain subterranean conditions, such as elevated temperatureand time, to effect a viscosity reduction of the fracturing fluid. Sincethese organic breaker chemicals work on chemical change, such ashydrolysis, they are slow in effecting viscosity reduction. Furthermore,their performance can be unpredictable.

Accordingly, the incorporation of a breaker chemical into the fracturingfluid prior to the pumping of the fracturing fluid into the wellbore andwell fractures is desirable. The breaker chemical must be in a passive,non-reactive state such that it cannot react with the viscous fluid ofthe fracturing fluid into the fractures, but the breaker chemical mustbe capable of reacting with the viscous fluid of the fracturing fluidwithin the fracture upon the completion of the fracturing process. Thepresent invention teaches a method of accomplishing this objective.

In order to effect delayed reaction with the polymer used to gel thefracturing fluid, the breaker material is sometimes coated as describedin U.S. Pat. Nos. 3,163,219; 4,506,734; and 4,741,401 and applicationSer. No. 637,401, filed Jan. 4, 1991 (now U.S. Pat. No. 5,102,558). Theencapsulation adds to the expense. Moreover, the coating of smallparticulates is difficult. U.S. Pat. No. 3,163,219 also discloses theuse of water-soluble or oil-soluble binders that are dissolved in thefracture; and U.S. Pat. No. 4,202,795 discloses pellets containing amixture of hydratable gelling agent (e.g., guar gum) and a breaker forthat gelling agent.

SUMMARY OF THE INVENTION

The method of the present invention involves the use of agglomeratedparticles referred to as granules containing a gel breaker which areintroduced into a well treating fluid and function as delayed breakersin well treating operations. The granules exhibit a delayed release ofthe active chemical (gel breaker) so the degradation of the polymeroccurs well after the fracturing fluid or gravel packing fluid has beenpumped into the formation. Moreover, the breakers are effective withinreasonable time periods so that long shut-in times are not required.

The granules comprise 40 to 90 percent of a solid (particulate) breakercompound (preferably an oxidizer), from 10 to 60 percent of an inorganicpowdered binder such as clay, and a small amount of an organicbinder/processing aid. The powdered binder preferably is made up of amixture of clay, talc and infusorial earth such as diatomaceous earth.

In the preferred embodiment of the invention, the granules contain amajor percentage of the breaker compound such as sodium persulfate orammonium persulfate. This high concentration of the breaker chemicalcoupled with inorganic clays, or mixtures containing clay, surprisinglyresults in a delayed release of the breaker compound thereby permittingthe well treating operation to be completed before the gel is broken.The breaker is activated by the well treating fluid dissolving thesoluble breaker. As more and more of the breaker is dissolved, theparticles disintegrates exposing more of the breaker compound to theliquid.

As mentioned above, the granules containing the breaker are introduceddirectly into the gelled well treating fluid as the fluid is pumped fromthe surface to and into the subterranean formation. The granule sizes ofthe particles containing the breaker are ideally suited for fracturingand gravel packing operations, ranging from 10 to 80 mesh (U.S. SieveSeries), more preferably from 12 to 60 mesh, and most preferably from 20to 40 mesh. The breaker may be incorporated into the frac sand or gravelslurry or into the fluid without the frac sand or gravel (e.g., padfluid).

BRIEF DESCRIPTION OF THE DRAWINGS

FIGS. 1, 2 and 3 are plots comparing the delayed release of breakerchemical from the granules with that of ungranulated breaker crystals.

DESCRIPTION OF THE PREFERRED EMBODIMENTS

The granules useful in the present invention are agglomerates of twomain powdered (finely divided) particulates: a breaker compound andinorganic binder. For clarity of description, the agglomerated particlesare referred to herein as "granules" and the constituent particulatesare referred to merely as particles or powder. The main components ofthe granules, the method of manufacture and method of use are describedin detail below.

Breaker Compound: Specific examples of preferred breaker compounds ofthe instant invention are selected from the group consisting of ammoniumand alkali persulfates, alkyl formates, salicylates, acetates,chlorites, phosphates, sulfamic acid, laureates, lactates,chloroacetates, enzymes and other solid breakers. These solids areavailable in particulate form and are capable of being granulated oragglomerated to form delayed breaker granules.

The preferred breakers are the crystalline particulates such as sodiumpersulfate and ammonium persulfate. It should be noted that sodiumpersulfate and many of the particulate breakers are too small inparticle size (generally smaller than 100 mesh) for effective coating bythe prior art techniques. Moreover, such particles present handlingproblems since they are so tiny. Also, the crystalline forms of thesesolids are generally angular which also contributes to difficulties inhandling and encapsulating.

The chemical breaker solids may be used per se in the agglomerationprocess to form the granules or, in other embodiments, may be depositedon or in a particle which functions as a core, seed, or carrier for thebreaker in the agglomeration process. For example, the breaker chemicalmay be sprayed as a solution or in liquid form onto small, finelydivided seed particles to form a coating on or in these seed particles.Essentially, any solid which is of the proper size and which is inert tothe breaker chemical (or other active material) may be used as the seed,core, or carrier particle, but urea is preferred. This embodiment isespecially preferred where the breaker chemical is itself a liquid.

By way of another example, the breaker chemical can also be used in acarrier particles with a solid polymeric matrix as described in U.S.Pat. No. 4,738,897 (incorporated herein by reference), or absorbed on orin a porous solid such as diatomaceous earth or coated on an inert coresubstrate such as urea as described above.

In another embodiment of this invention, the agglomerated granulescontaining breaker chemical, with or without a seed, core or carrier maybe overcoated or encapsulated with a thermoplastic polymer material. Thepreferred coating or encapsulation is as described in U.S. patentapplication Ser. No. 637,401, now U.S. Pat. No. 5,102,558, filed Jan. 4,1991, the disclosure of which is incorporated herein by references.

For purposes of the present invention the term chemical breakercompounds refers to the constituent particles (e.g., crystals, core,seed, carrier) in the agglomerated granules.

The preferred breaker chemicals for use in the present invention includeoxidizers such as ammonium persulfate, sodium persulfate, potassiumpersulfate, sodium chlorite, ammonium bifluoride, ammonium fluoride,sodium fluoride, potassium fluoride, sulfamic acid, citric acid, oxalicacid, ammonium sulfate, sodium acetate and enzymes and mixtures thereof.

The preferred oxidizer are the persulfates (sodium and ammonium) whichare commercially available. Sodium persulfate, for example, is availablein crystalline form (average particle size between 150 to 50 microns)and are typically available in 85%-95% pure form. Each granule used inthe present invention contains at least 3 particles, and preferably from5 to 30 particles, of the breaker compound, and most preferably 8 to 15particles.

Binders: The binder must be chemically nonreactive with the welltreating fluid and the breaker compound. The preferred binders arepowdered inorganic binders which are classified as nonchemical or inertbinders (i.e., they do not react with the constituent particles toachieve agglomeration).

The inorganic powdered binder functions to bind the particulate breakercompound together and increase the strength and integrity of thegranules. The powdered binder, also, provides a microporous matrix forconducting the carrier liquid (e.g., water) by capillary attraction tothe interior of the granule thereby enabling the liquid to contact thebreaker compounds. Therefore, the dissolution of the breaker is bycontacting the granule surface and/or interior.

Because its availability and effectiveness in granulation, clay is thepreferred binder for use in the present invention. The term "powdered"or "powder" means tiny particles having an average particle size of 10to 50 microns, preferably 20 to 40 microns. Clays (bentonite andattupulgate) are easily wet by water and are capable of being granulatedwith high levels of breaker compounds to form relatively strong granulesof the proper size for use in well treating operations.

In serving as the binder, the clay particles develop agglomerationforces by surface tension of the water present, adhesion forces, andelectrostatic forces. Other inorganic binders include sodium silicate,colloidal alumina, colloidal silica, fullers earth, and the like.

In addition to the principal binder, other particulate additives whichimprove the strength and function of the granule or aids in theprocessing may be used. Talc, which is magnesium silicate hydrate,functions as a binder and as a solid lubricant in the granulationprocess.

Infusorial earth (e.g., diatomaceous earth) appears to improve thestrength of the granules. Infusorial earth is a powder which is capableof holding four times its weight in water. Although it is not fullyunderstood why the presence of infusorial earth improves the performanceof the granules, it is believed that the high uptake of water ties upand distributes the water throughout the granule, and thereby stabilizesthe granules. Infusorial earth includes siliceous earth, diatomaceousearth, fossil flour, celite, kieselguhr, and the like.

It is necessary that the mixture of particles comprising the granulesinclude a small amount of an organic binder/processing aid. The organicbinder serves as a processing aid in the granulation process and as abinder in the final granule. Because of hazards involved in thegranulation process, it is necessary that the organic material selectedas the binder/processing aid be substantially non-oxidizable. Thenon-oxidizable character also increases the shelf life of the granules.Polyvinyl pyrrolidone (PVP), polyvinyl alcohol, a thermoplastic resin,or thermosetting resin are substantially non-oxidizable and thereforepreferred.

Manufacture of the Granules: The granules useable in the present may beagglomerated by a variety of well known processes including granulation,pelletizing, briquetting, and the like.

The preferred method of agglomerating the particles and powders intogranules is by low pressure granulation. Granulation is defined as theformation of small particles called granules by growth agitation. Inthis process, particles of the breaker compound and binder powder aremoistened and intimately mixed. The substantially homogeneous mixture isextruded at low pressure (e.g., below 100 psig) through screen openingsforming cylindrical extrudate pellets which are then subjected tospheronization treatment to reform them into generally spherical orrounded shapes. Low pressure granulation avoids the hazards ofdecomposing the unstable persulfates.

Briefly, the extrusion phase of the granulation process involvesintroducing a mixture of the breaker particles and binder powder wetwith about 1 to 30, preferably 5 to 25, most preferably 5-10 percentwater (based on the weight of the mixture) into an extruder hopper. Themoist mixture is fed into the feed zone of an auger-like screw extruderwhich mixes and kneads the mixture to disperse the solids uniformly intoa moist generally homogeneous mass. The screw auger transfers the massto the compression zone of the extruder where the particles arecompacted together, forcing air out of the voids. (Separate mixingaugers and compression augers may also be used.)

The compacted moist mass is then forced or extruded radially through ascreen forming generally cylindrical pellets which may be separated fromthe extrudate by breaking off by gravity, or by a blade which separatesthe extrudate from the screen.

The generally cylindrically shaped pellets are not suitable for handlingor for use in well treating operations. The extrudate pellets aretherefore subjected to spheronizing which may be as follows: The dampextrudate pellets are fed into equipment referred to as a spheronizer,where they are reshaped or deformed into well rounded or sphericalshapes. The pellet deformation may be carried out in a rotating bowlwith a friction plate. The pellet collisions with each other and withthe wall and contact with the friction plate imparts kinetic energy tothe pellets which gradually reform the pellets into generally sphericalshape. The granulation of powdered granules is described in detail in anarticle "EXTRUSION AND SPHERONIZING EQUIPMENT" by Douglas C. Hicks,presented at a seminar sponsored by The Center for ProfessionalAdvancement on Apr. 24-26, 1989 in Princeton, N.J. The disclosure inthis article is incorporated herein by reference.

Following granulation, the rounded granules may be screened for sizingand are dried to remove the water and thereby provide for sufficientstorage time before use.

Although granulation, as described above, is the preferred process ofmanufacturing process, other agglomeration processes may be used. Theseinclude pelletizing, fluid bed granulating, pan or drum granulating, andbriquetting. Tests have shown, however, that the low pressure extrusiongranulation produces moderately strong granules possessing a balance ofstrength to (a) endure the rigors of handling and pumping and (b)release of the soluble breaker compound upon contact with the fracturingfluid. The high pressure agglomeration processes are expensive andproduce agglomerates which may be not release the breaker compoundwithin the time constraints of a fracturing operation or other welltreating operation.

As mentioned above, the mixture of particles that are agglomerated intogranules may include primarily the breaker chemical solids, clayparticles, and an organic binder/processing aid.

Preferably, however, the dry mixture granulated will be as follows:

    ______________________________________                                                                 MOST                                                                PREFERRED PREFERRED                                                           WT %      WT %                                                 ______________________________________                                        Breaker Chemical Compound                                                                      40-90       more than                                                                     50 to 85                                         Binder powder                                                                 Clay (at least 40% of                                                                          8-58        10-30                                            the binder)                                                                   Talc             0-10        3-10                                             Infusorial Earth 0-10        2-10                                             Organic Binder/Processing Aid                                                                  0.1-2.0     0.2-1.0                                          ______________________________________                                    

For use in the method of the present invention, the granules, preferablyshould exhibit the following properties:

    ______________________________________                                        Particle Size      10 to 80 mesh                                              Strength or Hardness                                                                             about .5 to about 16                                       (particle crush    pounds                                                     strength*)                                                                    S.G. (particle)    2.0-3.0                                                    Delayed Release Time                                                                             reduction of 2 to 20                                                          (most preferably 2-15)                                                        times vis-vis                                                                 ungranulated crystals.                                     ______________________________________                                         *Penwalt Stokes Hardness Tester (U.S. Pat. No. 2,041,869)                

OPERATION

In carrying out the method of the present invention as applied inhydraulic fracturing operations, a subterranean formation is fracturedusing conventional equipment and fluids and processes. Typicalfracturing fluids include water-based brine fluids containing awater-soluble polymer such as hydroxypropyl guar crosslinked with atransition metal salt as is well known in the art. Other polymers usedto viscosify aqueous fracturing fluids are guar gum hydroxyethylcellulose, polyacrylamide, gum karaya and the like. In addition,fracturing fluids may be viscous oils or oil-based emulsions as x-linkedgelled forms or liquid gel forms. Viscosification of these isaccomplished via addition of surfactants, aluminum alkyl phosphates,asphalts, fatty-acid soaps, other emulsion and foam stabilizing agentsand the like.

Typical propping agents used in hydraulic fracturing for retaining theintegrity of the fractures are sand, sintered ceramics (e.g., sinteredbauxite), resin coated sand or combinations having a particle sizebetween 10 to 80 mesh. The concentration used depends on the size andshape of the proppant, the type of formation being fractured, thecarrying capacity of the fracturing fluids and the desired permeabilityof the resistant fractures. The concentrations generally range from 1 to30 pounds per 1000 gallons.

Other additives commonly used in hydraulic fracturing fluids are fluidloss or wall building agents such as starch, bentonite, silica flour,guar gum and surfactants; friction-reducing agents such as small amountsof high molecular weight linear polymers such as polyacrylamide;specific gravity increasing agents; bactericides;scale-removal/prevention agents, and surfactants or alcohol to reduceinterfacial tension and the resistance to return flow.

The granules containing the chemical breaker may be employed in thegelled fracturing fluid. The concentration of the granules should besufficient to provide the fracturing fluid with from 0.1 to 20 poundsper 1000 gallons of the fracturing fluid. Preferably, from 1 to 15pounds, and most preferably, from 2 to 10 pounds of granules are usedper 1000 gallons of fracturing fluid.

The process of the present invention may be carried out at formationtemperatures between 80 degrees Fahrenheit and 225 degrees Fahrenheit,preferably at high temperatures (above 140 degrees Fahrenheit). For lowtemperatures, the fracturing fluid may include an activator such astriethanolamine as taught in U.S. Pat. No. 4,250,044 for persulfates toaccelerate the activation of the breaker, the disclosure of which isincorporated herein by reference.

Following the pumping operation, the well is shut in permitting thefracturing fluid in the fracture to bleed off and the fracture tocollapse on the proppant. After a sufficient period of time, to permit aportion of the breaker chemical to be dissolved in the fracturing fluidor formation, the well is back flowed. The degradation of the polymer bythe action of the breaker chemical reduces the viscosity of thefracturing fluid permitting the fluid to be withdrawn from fracture bythe back flowing operations. The granules as dissolution proceedsdisintegrate, exposing more of the breaker chemical to the fracturingfluid.

EXAMPLES

Iodometric titration tests were carried out to demonstrate the delayedrelease of the breaker chemical in an aqueous medium. These testscompared the release of sodium persulfate crystals with the release ofgranules containing sodium persulfates at three pH's: 10,7, and 4.

The crystals were obtained from FMC Corporation; and the granulescontained:

    ______________________________________                                                           AVG. WT %                                                  ______________________________________                                        Sodium Persulfate    about 75                                                 Powdered Binder (Clay,                                                                             about 24                                                 Talc, Diatomaceous Earth)                                                     Organic Binder (PVP) about .5 to 1.0%                                         ______________________________________                                    

The titration tests involved preparing bottle samples containing abuffer and KI solution. The pH of each sample was adjusted to the testconditions (4,7, or 10) and one gram of the ungranulated crystals or 1gram of the granules were added to a bottle sample. Each sample wastitrated with 0.1N sodium thio sulfate until color changed from reddishyellow to clear. Titrations were performed on each sample at thefollowing typical time intervals: 1 min., 5 min., 10 min., 20 min., 40min., 60 min., and 80 min. The bottle samples were weighed before andafter titration to determine titrate used from which the amount ofsodium persulfate in solution was calculated. Replicate samples weretested at each condition.

During the tests, the granules were observed to disintegrate asdissolution of the sodium persulfate proceeded.

The test results are presented in TABLE I and graphically illustrated inFIGS. 1, 2, and 3 for pH's of 7, 10, and 4, respectively.

                  TABLE I                                                         ______________________________________                                        RELEASE RATE OF SODIUM PERSULFATE BREAKERS                                                    LOG % PER-                                                    FORM OF         SULFATE RELEASE NORMALIZED                                    BREAKER  pH     PER MINUTE (1)  RATE (2)                                      ______________________________________                                        Crystals 4      0.120           5.22                                          Granules 4      0.049           2.13                                          Crystals 7      0.264           11.5                                          Granules 7      0.049           2.13                                          Crystals 10     0.244           10.6                                          Granules 10     0.023           1.00                                          ______________________________________                                         (1) Percent Persulfate Released is the amount of persulfate released at a     given time divided by the total persulfate released expressed as a            percentage.                                                                   (2) Rates Normalized to slowest rate, granules at pH = 10.               

As illustrated in the plots of FIGS. 1, 2, and 3, the granules delayedrelease of breaker by several fold. The data in TABLE I reveals that thegranules reduced breaker release by about 21/2 times (pH of 4), by about5 times (pH of 7), and by about 10 times (pH of 10) compared to theungranulated crystals under the same conditions.

In order to demonstrate the effectiveness of the granules containingbreaker compound, tests simulating fracturing treatment were carriedout. The materials used in the simulation were:

Fracturing Fluid: Water gelled with 40 pounds guar/1000 gallons KCl (pH10)

Proppant: 20/40 mesh Carbo-Lite proppant

Breaker: 25/80 mesh granules with 75% sodium persulfate.

During a fracturing fluid simulation, the base gel was fed to an openblending device by the Moyno Pump where the fluid was stirred with aribbon-shaped stirring device. At this point, the breaker (2.0 lb ofgranules per 1000 gal of water) was added to the base fluid prior to theintensifier pumps. The crosslinking was accomplished by adding 2gal/1000 gal of a borate source equivalent to 0.8 lb/1000 gal boron witha high pressure metering pump on the high pressure side of theintensifier system.

The fluid proceeded from the intensifier pumps to a length of 1/4 inchtubing where it was sheared at a shear rate near 1000/sec for 5 minutesto simulate pumping down tubing at 12 BPM. The fluid then entered alength of 1 inch tubing surrounded by a heating jacket to simulate theformation. The shear rate was 40-50/sec while undergoing heat-up to thetemperature used for the fluid loss simulation. A temperature of 100degrees Fahrenheit was selected to represent the average cool-downtemperature of a point within 50 feet of the wellbore in formations witha BHT of 160 degrees Fahrenheit. Residence time in the formationsimulator was approximately 5 minutes.

Once the fluid was heated at a shear rate of 40-50/sec, it flowedthrough the test cell, again at a shear rate of 40-50/sec. Flow wasbetween two approximately 3/8 inch slabs of Ohio Sandstone core that hadbeen saturated with 2% KCl. The leakoff rate through each core wasmonitored vs time. The fluid traveled to a series of high pressureknock-out pots where the fluid was collected and dumped whilemaintaining a constant pressure of 1000 psi on the system.

A complexed gel pump time of 60 minutes was performed on all reportedtests. The time was divided into the following stages:

    ______________________________________                                        STAGE        FLUID          TEST                                              ______________________________________                                        1            2% KCl         10 min.                                           2            Base Gel       10 min.                                           3            Complexed Gel Pad                                                                            60 min.                                           4            Slurry to pack cell to                                                        desired concentration                                            ______________________________________                                    

The amount of proppant was selected to obtain 2 lb/sq.ft. in the 1/3inch slot. The final slurry was flowed into the cell and the cellshut-in. The pipe-to-slot flow ends were removed and replaced with theinserts containing a 1/8 inch hole with a filter screen to confineproppant to the cell during closure. The top piston set-screws andspacers were removed and an increasing closure pressure was appliedwhile heating to the test temperature of 160 degrees Fahrenheit andmonitoring leakoff. A closure pressure of 1000 psi was achieved over thecourse of 100 minutes.

Fluid was leaked off until a net cell pressure of zero was obtained(closure-internal cell pressure=0). At this point, the cell was shut-inat temperature and allowed to set static for 12 hours. After 12 hours,2% KCl flow was initiated through the core and the pack simulatingflowback while closure was slowly increased to 2000 psi, according tothe test parameters. Fluid was flowed alternately through the core andthe pack for 24 hours. Thereafter, conductivity and permeability of thepack was monitored vs time for 50 hours.

The data is presented in TABLE II.

                                      TABLE II                                    __________________________________________________________________________    HOURS AT                                                                      CLOSURE & CLOSURE                                                                             TEMP CONDUCTIVITY                                                                            WIDTH                                                                              PERMEABILITY                              TEMPERATURE                                                                             (psi) DEG F.                                                                             (md-ft)   (in) (Darcies)                                 __________________________________________________________________________    -24       1000  100-150                                                                            Leakoff while heating & breaking                         -18       1000  150  --        0.229                                                                              --                                        -6        1000  150  --        0.227                                                                              --                                         0        2000  150  7231      0.225                                                                              386                                       10        2000  150  6507      0.224                                                                              349                                       20        2000  150  9142      0.223                                                                              492                                       30        2000  150  9590      0.223                                                                              516                                       40        2000  150  9670      0.223                                                                              520                                       50        2000  150  9670      0.223                                                                              520                                       __________________________________________________________________________     Note: 50 hour KCl Retained Permeability = 520/567 92%                    

The TABLE II data indicated that the breakers were effective in reducingthe viscosity of the fracturing fluid and achieving 92% of theconductivity of the proppant packed fracture.

Additional tests were carried out in a rheology simulator to determinewhether or not the delayed release of the breaker from the granules usedin the experiments described above was sufficient to permit placement ofthe viscosified fracturing fluid in the formation.

The base gel was pumped to the blender where marker proppant, 20/40sand, and breaker were added. The slurry was then pumped with a triplexpump through 0.899 inch coiled tubing at 15 gal/min (1300 1/sec) to thechoke table where it is split to load the formation simulator at 5gal/min (196 1/sec). The residence time in the tubing simulator was 2.5min and the bath temperature was 85 degrees Fahrenheit. Once theformation simulator was loaded, the intensifier pump was shut down. Thetest gel was displaced through the rheometer by a small triplex pump. Alow rate, 0.5 to 1 gal/min, was maintained through mots of the test. Thetemperature of the fluid coming out of the formation simulator wasadjusted to 150 degrees Fahrenheit initially and rampled to 160 degreesFahrenheit during the test to give the desired temperature range. Therheology was determined with a 4-pipe sequential rheometer. The fluidfirst entered 20.474 ft of 0.93 inch ID tubing and then 13.533 ft of0.807 inch ID pipe, 11.021 ft of 0.674 inch ID tubing and, finally,6.291 ft of 0.615 inch ID pipe. Each pipe had two DP-15 Validynepressure transducers. The test fluid then goes through a mass flow meterwhere rate and density are recorded, and on to the slot, where the testis video taped. The rate was measured with a Micro-Motion D-40 mass flowmeter. The 8 dP's, temperature, density, and rate were routed to aValidyne MCI-20 signal conditioner then to a Validyne DA-380. The datawas then sent to a IBM-PC where it was stored on disk for later use.

These tests indicated that the fracturing fluid retained its viscosityafter 37 minutes, which for most operations is sufficient to completepumping of the gelled fracturing fluid.

The breaker should delay degradation of the gel for at least 30 minutes,preferably 60 minutes, and should complete the release (by dissolution)of the breaker within 360 minutes. "Complete release" is defined whereat least 99% of the breaker has been dissolved and diffused into thesurrounding fracturing fluid. The above tests demonstrate that thegranules exhibit (a) sufficient reaction to permit safe placement of theproppant and (b) sufficient release of the breaker to effect degradationof the gel and provide at least 90% of the retained propped permeability(i.e., permeability without gel).

OTHER EMBODIMENTS

While the present invention has been described with specific referenceto gelled aqueous fracturing fluids, it will be appreciated by thoseskilled in the art that the principles embodied in the present inventionwill have applications in any well treating operation where a gelledfluid is pumped into a subterranean formation and is degraded within arelatively short period of time to remove the gelled fluid and improveor restore the conductivity or permeability in the formation. Two suchwell treating operations are fracturing and gravel packing. Also, themethod can be used with water-base or oil-base fluids, with the formerbeing preferred.

What is claimed is:
 1. In a method for treating a subterranean formationwherein a fluid gelled with a polymeric gelling agent is injectedthrough the wellbore and into the subterranean formation, theimprovement wherein the fluid contains agglomerated granules having anaverage particle size between 10 to 80 mesh, said granules comprisingfrom 40 to 90 weight percent of a particulate chemical breaker compoundcapable of degrading the polymeric gelling agent, from 8 to 58 wt % ofan inert inorganic binder powder, and from 0.1 to 2 wt % of an organicbinder/processing aid.
 2. The method of claim 1 wherein the gelled fluidis an aqueous fracturing fluid.
 3. The method of claim 2 wherein thechemical breaker compound is an oxidizing agent capable of degrading thepolymeric gelling agent.
 4. The method of claim 2 wherein the oxidizingagent is a persulfate.
 5. The method of claim 2 wherein in granulescomprise more than 50 wt % of the particulate chemical breaker compound.6. The method of claim 2 wherein the granules are made by low pressuregranulation.
 7. The method of claim 1 wherein the granules each have acrushing strength of 0.5 to 16 pounds.
 8. A method of fracturing asubterranean formation which comprising(a) injecting into the formationan aqueous fracturing fluid viscosified with a polymeric gelling agentat sufficient rate and pressure to form a vertical fracture therein; (b)injecting into the fracture additional fracturing fluid containing amixture of a propping agent and granules having an average particle sizeof between 10 to 80 mesh and comprising an agglomeration of particles ofparticulate oxidizing agent, particles of an inert inorganic powder, andan organic binder/processing aid; said oxidizing agent being watersoluble and capable of degrading the gelling agent; (c) permitting thefracturing fluid to dissolve a portion at least of the oxidizing agentto degrade the gelling agent thereby reducing the viscosity of thefracturing fluid; and (d) backflowing the degraded fracturing fluid tothe surface.
 9. The method of claim 8 wherein the oxidizer is apersulfate oxidizer having an average particles size of between 50 to150 microns and the binder powder includes clay.
 10. The method of claim9 wherein the granules contain a major wt % of the persulfate oxidizerand a minor wt % of the binder powder.
 11. The method of claim 8 whereinthe granules have a time release property in an aqueous medium wherein99% of the oxidizer is released from the granule between 30 minutes and360 minutes after introduction into the fracturing fluid.
 12. The methodof claim 8 wherein the granules are present in the fracturing fluid at aconcentration of 0.1 to 20 pounds per 1000 gallon.
 13. In a method fortreating a subterranean formation wherein a fluid gelled with apolymeric gelling agent is injected through a wellbore and into thesubterranean formation, the improvement wherein the fluid containsagglomerated granules having an average particle size between 10 to 80mesh, said granules comprising from 40 to 90 weight percent of aparticulate chemical breaker compound capable of degrading the polymericgelling agent, from 8 to 58 wt % of clay, from 0 to 10 wt % talc, from 0to 10 wt % infusorial earth, and from 0.1 to 2 wt % of an organicbinder/processing aid.